25th Annual Credit Suisse Energy SummitMarch 2, 2020

N Y S E : D N R 2

Forward-Looking Statements: The data and/or statements contained in this presentation that are not historical facts are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as

amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, financial forecasts, future hydrocarbon prices and their volatility, current or future liquidity

sources or their adequacy to support our anticipated future activities, our ability to refinance or extend the maturities of our long-term indebtedness which matures in 2021 and 2022, possible future write-downs of oil and natural gas

reserves, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows or the impact of changes in commodity prices

on cash flows, availability of capital, borrowing capacity, price and availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or

methods, including the timing and location thereof, the nature of any future asset purchases or sales or the timing or proceeds thereof, estimated timing of commencement of CO2 flooding of particular fields or areas, including Cedar

Creek Anticline (“CCA”), or the availability of capital for CCA pipeline construction, or its ultimate cost or date of completion, timing of CO2 injections and initial production responses in tertiary flooding projects, development

activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves

and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, levels of tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of

regulatory rulings or changes, outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, the actual or anticipated future drop in oil demand in China

due to the COVID-19 coronavirus, competition, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions, the likelihood and extent of an economic

slowdown, and other variables surrounding operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,”

“anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon

management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions

and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on

our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; evolving

political and military tensions in the Middle East; decisions as to production levels and/or pricing by OPEC or production levels by U.S. shale producers in future periods; levels of future capital expenditures; trade disputes and resulting

tariffs or international economic sanctions; effects and maturity dates of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; access to and or terms of credit in the commercial banking or

other debt markets; fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well incidents,

hurricanes, tropical storms, forest fires, or other natural occurrences; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economic conditions;

competition; government regulations, including changes in tax or environmental laws or regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are

otherwise discussed in this presentation, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements.

Statement Regarding Non-GAAP Financial Measures: This presentation also contains certain non-GAAP financial measures including free cash flows, adjusted cash flows from operations, adjusted EBITDAX, and PV-10. Any non-GAAP

measure included herein is accompanied by a reconciliation to the most directly comparable U.S. GAAP measure along with a statement on why the Company believes the measure is beneficial to investors, which statements are

included at the end of this presentation.

Note to U.S. Investors: Current SEC rules regarding oil and gas reserves information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s

definitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2018 and December 31, 2019 were estimated by DeGolyer and MacNaughton, an independent

petroleum engineering firm. In this presentation, we may make reference to probable and possible reserves, some of which have been estimated by our independent engineers and some of which have been estimated by Denbury’s

internal staff of engineers. In this presentation, we also may refer to one or more of estimates of original oil in place, resource or reserves “potential,” barrels recoverable, “risked” and “unrisked” resource potential, estimated

ultimate recovery (EUR) or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include estimates of resources that do not rise to the

standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than

estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.

Cautionary Statements

N Y S E : D N R 3

Uncommon Company, Extraordinary Potential

• Favorable crude quality & premium pricing• Industry leading oil weighting• Top quartile operating margins

Extreme Oil Gearing

CO2 EOR:A Sustainable

Business Model

• Vertically integrated EOR infrastructure• Cost structure independent from industry• Operating in unconstrained basins

Strategically Advantaged

Operations• >400 MMBbl EOR potential at CCA• Inventory of EOR development opportunities• Short-cycle exploitation opportunities

Significant Organic

Growth Potential

Financial Discipline• Generating significant free cash flow• Strong liquidity and improving leverage profile• Quality asset base provides capital flexibility

• We achieve net negative carbon emissions through associated storage of industrial-sourced CO2

• Aligned with international CO2 emission reduction efforts

• Assets and expertise well-suited for future carbon capture

N Y S E : D N R 4

Plano HQ

CO2 Sources

Denbury Owned Fields

Planned CO2 Pipelines

Current CO2 Pipelines

A Unique Energy Business• ~65% of production via CO2 enhanced oil recovery (EOR)• Vertically integrated CO2 supply and distribution• Cost structure largely independent from industry

Industry Leader in Reducing CO2 Emissions• Annually injecting >3 million metric tons of industrial-

sourced CO2 into our reservoirs• Potential to reach full carbon neutrality this decade with

CCUS, including downstream Scope 3 emissions

Fundamentally Geared to Crude Oil• 97% oil, high exposure to Gulf Coast premium pricing• Superior crude quality (Mid-30’s API gravity, low sulfur)

Relentless Focus on Execution and Results• Highly economic project portfolio at $50 oil• Significant debt reduction and cost structure improvements

since 2014• Track record of spending within cash flow

Value Sustaining with Organic Growth Upside• Over 1 billion BOE proved + EOR and exploitation potential

Denbury – What We Are

Gulf Coast Region

Rocky Mountain Region

4Q19 Production

57,511 BOE/d

YE19 Proved O&G Reserves

230 MMBOE$2.6B PV-10 Value

YE19 Proved CO2 Reserves

5.9 Tcf

N Y S E : D N R 5

An Industry Leader in Reducing CO2 Emissions

Combined Scope 1 & 2 Emissions

1.8 million metric tonsCaptured Industrial Sourced CO2

3.3 million metric tons – 1.5 million metric tonsNet Negative CO2 Emissions

– =

Full Company Net Negative in 2018 - Combined Scope 1 and Scope 2 CO2 Emissions

~30% of our CO2

is industrial sourced

The only U.S. public company of scale where injecting CO2 into the ground to produce oil is our primary business

Environment

N Y S E : D N R 6

Sustainably Leveraging the Denbury Difference

Social

0

0.5

1

1.5

2

2014 2015 2016 2017 2018 2019

Total Recordable Incident Rate (TRIR)

Consistent sustainability reporting (2014-2018) in accordance with GRI StandardsOur most recent Corporate Responsibility Report can be accessed on our website at: csr.denbury.com

GOVERNANCEISS

RATING “1”

We maintain a long-standing commitment to the highest standards for the safety and development of our employees,

contractors and local communities

• Achieved our best Total Recordable Incident Rate (TRIR) in 2019

• Safety targets explicitly tied to executive compensation

• Comprehensive training and development program including safety, leadership, and diversity training

• Matched >$250,000 employee charitable donations over last 5 years

• Chaired 2019 Dallas Heart Walk for the American Heart Association

Governance

• 7 out of 8 directors are independent, including independent Chairman of the Board

• Long-standing female board representation since 2012

• ISS Governance Rating of “1” (Best Possible)

• Code of Conduct and Ethics Rated “A” by NYSE Governance Services (Top 1%)

Strong corporate governance is essential to fulfilling our obligations to our stakeholders and to operating as a

responsible corporate citizen

N Y S E : D N R 7

Differentiated Oil Quality & Market Access

✓ Mid-30’s API Gravity

✓ Low Sulfur Content (< 0.5%)

✓ Ideal for U.S. Refineries

✓ Highly Sought After for Blending with Ultra Light Crude

✓ Outside Constrained Basins

✓ ~60% of Production Receives Gulf Coast Premium Pricing

✓ Established Pipeline Takeaway Infrastructure

✓ Access to Diverse Markets

Premium Quality Geographically Advantaged

N Y S E : D N R 8

2020 Outlook & Objectives

Operations and Development Business Performance

Progress CCA EOR Development

• Install CCA CO2 pipeline

• Begin facility and well work

Drive Organic EOR Growth• Oyster Bayou A2

• Cranfield Phase 8

• Soso Rodessa

Operate Safely and Responsibly

• Continue to build on improvements in health, safety and environmental performance

Expand Exploitation Opportunity Set• Brookhaven Case Sand

• CCA Mission Canyon

• Gulf Coast JV, anticipated to close in March 2020

Sustained focus and progress on improving operational and business performance

Strengthen Balance Sheet$ • Address near-term maturities

• Continue to prioritize debt reduction

Disciplined Capital Management• Base capital budget designed to deliver

significant free cash flow at $50 oil

• Defer decision on contingent CCA EOR development capital until 2Q20

$

N Y S E : D N R 9

61%65%

62% 62%

47%

69%

51%

59%

33%

64%

49%

37% 37%

56%

DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M Peer N

Peer Average

Industry-Leading Oil Weighting

Source: Company filings for the fourth quarter ended 12/31/2019. Peers include CLR, CRC, CXO, DVN, LPI, MRO, MUR, NBL, OAS, PDCE, PXD, SM, WLL, and WPX.1) NGL production is not reported separately for this entity.

NGL Production

Oil Production

(1) (1) (1)

54% Oil

68% Liquids

(1)

98% Oil

Peer Average

4Q19 % Liquids Production

N Y S E : D N R 10

Source: Company filings for the fourth quarter ended 12/31/2019. 1) Operating margin calculated as revenues less lifting costs. Lifting costs calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes.2) Revenues exclude gain/loss on derivative settlements.

Leading Revenue and Operating Margin per BOE

$5

$10

$15

$20

$25

$30

$35

$40

$20 $30 $40 $50 $60 $70

4Q

19

Op

era

tin

g M

argi

n p

er

BO

E(1)

4Q19 Revenue per BOE(2)

DNR

Higher Revenue per BOE

Higher Operating

Margin per BOE

Peers include CLR, CRC, CXO, DVN, LPI, MRO, MUR, NBL, OAS, OXY, PDCE, PXD, SM, WLL, and WPX.

Denbury’s EOR-focused operations generate the highest revenue per BOE

among peers, driving a best-in-class operating margin

N Y S E : D N R 11

56%

20%

17%

39%

9%

5%

11%

11%

Capex LOE G&A Prod. Taxes & Transp.

Average of Peers(1)

FY19 Operating & Capital Spend as % of Oil & Gas Revenue

Lowest Spend Among Peers as a Percent of Revenue

75%

93%

Spe

nd

as

% o

f R

even

ue

1) Source: results from Company filings for the twelve months ended 12/31/2019. Peers include CLR, CRC, CXO, LPI, MUR, MTDR, OAS, PDCE, PE, PXD, SM, WLL, and WPX.2) G&A spend adjusted for approximately $18.6 million in severance-related expense associated with the Company’s voluntary separation program.See Appendix slide 36 for a detailed list of peers and selected operating and capital costs as a percentage of revenue.

Denbury’s differentiated, EOR-driven model drives the lowest spend as % of revenue across peers

Denbury’s high oil weighting & premium pricing exposure deliver highest revenue per BOE among peers

• Spend versus revenue is more effective metric than per-BOE comparisons given low natural gas and NGL pricing environment

• Metric directly drives free cash flow

Combined LOE & Capex lowest among peers

• EOR business model results in higher LOE but allows for superior flexibility in capital spend

• Combination of LOE and Capex ~20% lower than peer average

G&A spend ~44% below peer average(2)

• Sustained focus on efficiencies and cost reductions

N Y S E : D N R 12

2020 Base Capital Budget 25% lower than 2019

Tertiary

Oyster Bayou A2 Development Expansion 1Q-3Q

Cranfield Phase 8 Expansion Pattern 2Q-3Q

Soso Rodessa Development 2Q-3Q

Non-Tertiary

Brookhaven Case Sand Exploitation 2Q

CCA Mission Canyon Exploitation 3Q

Contingent CCA EOR Development

CCA Pipeline, Facilities & Well Work 2Q-4Q

Significant 2020 Capital ProjectsDevelopment Capital Budget(1)

1) Amounts presented exclude $40 - $45 million of capitalized interest.2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.3) Total CCA EOR development capital for the year is estimated to be $155 million, of which $145 million is subject to Board approval, anticipated to occur in second

quarter 2020.

In millions

$10

$40

$55

$75

CO Pipeline & Other Other Capitalized Items Non-Tertiary Tertiary2(2)

$27

$46

$71

$93

2019 Actual$237 Million

2020 Base Budget

$175 - $185 Million

$145

CCA EOR Development

2020 Contingent CCA EOR Budget

$140 - $150 Million(3)

(25%)

N Y S E : D N R 13

2020 Guidance

Development Capital Budget(1)

1) Amounts presented exclude $40 - $45 million of capitalized interest.2) Total CCA EOR development capital for the year is estimated to be $155 million, of which

$145 million is subject to Board approval, anticipated to occur in 2Q20.3) Includes capitalized internal acquisition, exploration and development costs and pre-

production tertiary startup costs.

Production (BOE/d)

2(3)

53,000 – 56,000

25% reduction in 2020 capital spend results in minor

production decline

56,914

2020E

2019Adjusted

Continuing Production(4)

4) 2019 Adjusted Continuing Production excludes 1,085 net BOE/d of non-tertiary production related to the sale of half of our nearly 100% working interests in Webster, Thompson, Manvel, and East Hastings fields, which is expected to close in March 2020 and 214 net BOE/d of non-tertiary production related to the sale of Citronelle Field, sold July 1, 2019.

Cash Flow @ $50 oil(5)

• Anticipate upwards of $100 million of free cash flow if only base capital budget is executed

5) Currently estimated ranges based upon forecasts and assumptions as of February 25, 2020.

6) Other cash resources includes $40 million of estimated proceeds from the Gulf Coast JV, anticipated to close in March 2020.

• Spending expected to be approximately neutral with cash flow and other cash resources(6)

if contingent CCA EOR development capital budget is approved

In millions

$10

$40

$55

$75

CO Pipeline & OtherOther Capitalized ItemsNon-TertiaryTertiary

2020 Base Budget

$175 - $185 Million

$145

CCA EOR Development

2020 Contingent CCA EOR Budget

$140 - $150 Million(3)

N Y S E : D N R 14

$2,852

$826

$346 $246

$246 $246

$1,521

$1,623 $1,623

$324

$185 $171

$167

$395

$50

12/31/14 12/31/18 9/30/19 12/31/19

Continuing to Improve Debt Profile

(In millions)

$553

$246

$51

$615

$58

$456

$136

2020 2021 2022 2023 2024

Sr. Subordinated NotesSr. Secured 2nd Lien Notes Convertible Sr. Notes

$666

$799

$136

$514

Sr. Secured Credit Facility

$3,571

Pipeline / Capital Lease Debt

$2,532

$1.3B debt reduction since 2014

$2,282

Debt Principal – 12/31/19 Maturity Window – 12/31/19(In millions)

$528 million of Bank Line Availability at 12/31/19 after $87 million of LCs

$2,436

$250MM debt reduction in 2019

N Y S E : D N R 15

12/31/19 12/31/18

Trailing 12 months Trailing 12 months

Adjusted EBITDAX(1) (millions) $607 $584

Net Debt Principal(2) (millions) 2,271 2,481

Net Debt/Adjusted EBITDAX(1) 3.7x 4.2x

Average Realized Oil Price ($/Bbl) $59.40 $57.91

Improved Leverage Metrics

Leverage Ratio

1) A non-GAAP measure. See press release attached as Exhibit 99.1 to the Form 8-K filed February 25, 2020 for additional information, as well as slide 42 indicating why the Company believes this non-GAAP measure is useful for investors.2) Net of cash & cash equivalents and debt issuance costs, and excludes future interest payable and unamortized debt discounts.

Half turn leverage ratio reduction in 2019

N Y S E : D N R 16

Hedge Positions – as of February 24, 2020

1) Averages are volume weighted.2) If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and sold put price.

Downside Protection with Significant Upside Potential 2020

1H 2H FYFi

xed

Pri

ce

Swap

sWTI NYMEX

Volumes Hedged (Bbls/d) 2,000 2,000 2,000

Swap Price(1) $60.59 $60.59 $60.59

Argus LLSVolumes Hedged (Bbls/d) 4,500 4,500 4,500

Swap Price(1) $62.29 $62.29 $62.29

3-W

ay C

olla

rs

WTI NYMEX(3)

Volumes Hedged (Bbls/d) 23,000 21,000 21,995

Sold Put Price(1)(2) $48.25 $48.26 $48.25

Floor Price(1) $56.95 $56.85 $56.90

Ceiling Price(1) $62.83 $62.68 $62.76

Argus LLS

Volumes Hedged (Bbls/d) 10,000 8,000 8,995

Sold Put Price(1)(2) $52.85 $52.75 $52.81

Floor Price(1) $61.52 $61.08 $61.32

Ceiling Price(1) $68.21 $68.39 $68.29

Total Volumes Hedged 39,500 35,500 37,490

% of FY20E Production Midpoint (BOE/d) 72% 65% 69%

Weighted Average Floor Prices

WTI NYMEX $57.24 $57.17 $57.21

Argus LLS $61.75 $61.52 $61.64

N Y S E : D N R 17

Gulf Coast Region

Reserves Summary(1) (MMBOE)

Proved + Tertiary Potential

Tertiary Reserves

Proved 118

Potential 285

Non-Tertiary Reserves

Proved 21

Total MMBOE(2) 424

Proved + Tertiary Potential by Field(3)

Mature Area 25

Conroe 130

Delhi 25

Hastings 30 – 65

Heidelberg 25

Manvel 10

Oyster Bayou 20

Tinsley 25

Thompson 20 – 40

Webster 40 – 75

W. Yellow Creek 5 – 10

Denbury Operated Pipelines

Denbury Planned Pipelines

Denbury Owned Fields – Current CO2 Floods

Denbury Owned Fields – Potential CO2 Floods

Fields Owned by Others – CO2 EOR Candidates

Industrial CO2 Sources

Naturally-Occurring CO2 Source

Note: See “Slide Notes” on slide 25 in the appendix to this presentation for footnote explanations.

N Y S E : D N R 18

Rocky Mountain Region

Reserves Summary(1) (MMBOE)

Proved + Tertiary Potential

Tertiary Reserves

Proved 21

Potential 539

Non-Tertiary Reserves

Proved 71

Total MMBOE(2) 631

Proved + Tertiary Potential by Field(3)

Bell Creek 20 – 40

Cedar Creek Anticline Area

400 – 500

Gas Draw 10

Grieve 5

Hartzog Draw 30 – 40

Salt Creek 25 – 35

Denbury Operated Pipelines

Denbury Planned Pipelines

Denbury Owned Fields – Current CO2 Floods

Denbury Owned Fields – Potential CO2 Floods

Fields Owned by Others – CO2 EOR Candidates

CO2 Resources Owned or Contracted

Pipelines Owned by Others

Note: See “Slide Notes” on slide 25 in the appendix to this presentation for footnote explanations.

N Y S E : D N R 19

CCA EOR – A Carbon Negative Development

Project Update

• Prepare to complete CO2 pipeline installation in 2020, subject to 2Q20 contingent funding approval

– Planned activities include installation of CO2

pipeline, facility infrastructure construction and well work

– $155 million total spend anticipated in 2020, assuming approval of contingent funding

• 100% planned use of industrial CO2 results in a development that is carbon negative, including downstream (Scope 3) CO2 emissions

• Evaluating further enhancements to project based on potential availability of additional CO2

• Continuing to evaluate both self-funding and JV options for the CO2 pipeline construction

$140 - $150 Million Contingent funding

decision planned for 2Q20

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

~7,500 - 12,500 net Bbls/d for Phase 1

Est. Incremental EOR Production

Future EOR Potential

Planned Phase 2Phase 1

N Y S E : D N R 20

Phase 5

• Initial phase response in 2018

• 2019 average production of ~2,300 net Bbl/d

Phase 6

• Commenced CO2 injection in April 2019

• Expect results similar to Phase 5

• First production response in 1Q20

Phases 1-4 Ongoing Exploitation

• High resolution seismic imaging identified multiple stranded areas of unswept oil

– Successful first well online in 1Q19

• IP30 ~600 Bbl/d

– Second well results expected in 1Q20

– Additional well planned for 3Q20

Continuing Field Development

Best rock quality in Phases 5 and 6

leads to greater production response

Phase 5

Phase 4

Phase 3

Phase 2

Phase 1

Bell Creek Production(Net Bbl/d) 3Q19 CO2

source maintenance turnaround

Bell Creek Update

N Y S E : D N R 21

Heidelberg Christmas Horizon Redevelopment

Targets Yellow and Brown Christmas sands

• Dedicated injector-producer patterns

• Repeating proven Heidelberg down-dip injection/up-dip production configuration

• ~3 MMBbl recoverable resource potential

• Total capital spend $28 million

Project milestones

• Commenced CO2 injection in December 2018

• First production 2Q19

• All wells online at the end of 2Q19

• Production response in line with forecast; current performance ~950 net Bbl/d

Redevelopment Overview

10 New Drill Wells

12 Workovers

7 Existing Wells

Heidelberg Formations

40’

40’

50’

60’

Existing Development

Existing Development

Future Development

N Y S E : D N R 22

Successful Brookhaven Case Sand Exploitation

First Well LocationTargeting Case Sand in Brookhaven Field

• Seismically identified channel within producing area

• Estimated drilling and completion cost ~$3MM/well

• ~1.3 MMBbl recoverable resource potential

Successful first well

• Drilled in late 4Q19, first production early 1Q20

• IP30 ~400 Bbl/d, >95% oil cut

Path forward

• Drill and complete 2 new wells in 2020

• Evaluate seismic data in other fields for similar potential

Brookhaven Case Sand

Initial Well IP30: 400 BOPD

Brookhaven Field

2020 Locations

Pilot Sand

Case Sand

Upper Smith Sand

Lower Smith Sand

Brookhaven FieldType Log

Brookhaven Case Sand

Case Sand Channel

N Y S E : D N R 23

Texas Conventional Oil Fields Farm-Down

Overview

• Contracted to sell half of our ~100% working interest in Webster, Thompson, Manvel, and East Hastings Conventional Fields

• Expect to receive ~$40 million in cash, after closing adjustments

• 100% capital carry to drill and complete initial 10 horizontal wells

– Overriding royalty interest of 6.25% for the first 10 wells retained until payout; 50% working interest after payout

– Potential future additional wells to be drilled and completed on a pro-rata working interest basis

Project milestones

• Closing expected in March 2020

• First well to be spud within 6 months of closing, all ten carried wells to be completed within 18 months

Transaction Details

Accelerates conventional exploitation with a capital carry on first 10 wells

Sale proceeds provide flexibility for debt reduction and capital program

Transaction Benefits

Houston

Manvel

Thompson

East Hastings

Webster

24N Y S E : D N R 24

Appendix

N Y S E : D N R 25

Slide Notes

Slide 17 – Gulf Coast Region

1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/19 SEC pricing. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/18, using the mid-point of ranges, based upon a variety of recovery factors and long-term oil price assumptions, which also may include estimates of resources that do not rise to the standards of possible reserves. See slide 2, “Cautionary Statements” for additional information.

2) Total reserves in the table represent total proved plus potential tertiary reserves, using the mid-point of ranges, plus proved non-tertiary reserves, but excluding additional potential related to non-tertiary exploitation opportunities.

3) Field reserves shown are estimated proved plus potential tertiary reserves.

Slide 18 – Rocky Mountain Region

1) Proved tertiary and non-tertiary oil and natural gas reserves based upon year-end 12/31/19 SEC pricing. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/18, using the mid-point of ranges, based upon a variety of recovery factors and long-term oil price assumptions, which also may include estimates of resources that do not rise to the standards of possible reserves. See slide 2, “Cautionary Statements” for additional information.

2) Total reserves in the table represent total proved plus potential tertiary reserves, using the mid-point of ranges, plus proved non-tertiary reserves, but excluding additional potential related to non-tertiary exploitation opportunities.

3) Field reserves shown are estimated proved plus potential tertiary reserves.

4) Timing of CCA CO2 pipeline installation is contingent on Board approval, which is currently anticipated to occur in 2Q20.

N Y S E : D N R 26

CO2 EOR can produce about as much oil as primary or secondary recovery(1)

CO2 EOR Process

17%

18%

20%

Rec

ove

ry o

f O

rigi

nal

Oil

in P

lace

(“

OO

IP”)

CO2 EOR(Tertiary)

Secondary (Waterfloods)

Primary

1) Based on OOIP at Denbury’s Little Creek Field

~

~

~

CO2 moves through formation mixing with oil, expanding and moving it toward producing wells

CO2 Pipeline

CO2 Injection Well Production Well

Oil Formation

N Y S E : D N R 27

CO2 EOR is a Proven Process

Jackson Dome

Bravo Dome

LaBarge

Lost Cabin

DGC

McElmo Dome

Naturally Occurring CO2 Source

Industrial-Sourced CO2

Air Products

Nutrien

Sheep Mountain

1) Source: Advanced Resources International for data through 2014; state EOR data 2015-2018.

Significant CO2 Supply by Region

Gulf Coast Region» Jackson Dome, MS (Denbury Resources)» Air Products (Denbury Resources)» Nutrien (Denbury Resources)» Petra Nova (Hilcorp)Permian Basin Region» Bravo Dome, NM (Kinder Morgan, Occidental)» McElmo Dome, CO (ExxonMobil, Kinder Morgan)» Sheep Mountain, CO (ExxonMobil, Occidental)Rocky Mountain Region» LaBarge, WY (ExxonMobil, Denbury Resources)» Lost Cabin, WY (ConocoPhillips)Canada» Dakota Gasification (Whitecap, Apache)

Significant CO2 EOR Operators by Region

Gulf Coast Region» Denbury Resources » HilcorpPermian Basin Region» Occidental » Kinder MorganRocky Mountain Region» Denbury Resources» Devon

» FDL» Chevron

Canada» Whitecap » Apache

Petra Nova

0

50

100

150

200

250

300

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018

MB

bls

/d

Gulf Coast/OtherMid-ContinentRocky MountainsPermian Basin

CO2 EOR Oil Production by Region(1)

N Y S E : D N R 28

Significant Running Room with CO2 EOR

1) Source: 2013 DOE NETL Next Gen EOR.2) Total estimated recoveries on a gross basis utilizing CO2 EOR.3) Using approximate mid-points of ranges, based on a variety of recovery factors.

33-83 Billion of Technically Recoverable Oil(1,2)

(amounts in billions of barrels)

Permian 9-21

East & Central Texas 6-15

Mid-Continent 6-13

California 3-7

South East Gulf Coast 3-7

Rockies 2-6

Other 0-5

Michigan/Illinois 2-4

Williston 1-3

Appalachia 1-2

Up to 83 Billion Barrels of Technically Recoverable Oil – U.S Lower 48(1)(2)

Denbury’s fields represent ~10% of total potential(3)

LA

3.7 to 9.1Billion BarrelsGulf Coast Region(2)

2.8 to 6.6 Billion Barrels

Rocky Mountain Region(2)

MT ND

WY

TX

MS

CO2 Source Owned or Contracted

Existing Denbury CO2 Pipelines

Planned Denbury CO2 Pipeline

Denbury owned oil fields

CO2 Pipeline owned by Others

N Y S E : D N R 29

Jackson Dome

– Proved CO2 reserves as of 12/31/19: ~4.8 Tcf(1)

– Additional probable CO2 reserves as of 12/31/19: ~0.9 Tcf

Industrial-Sourced CO2

Current Sources

– Air Products (hydrogen plant): ~45 MMcf/d

– Nutrien (ammonia products): ~20 MMcf/d

Future Potential Sources

– Lake Charles Methanol (methanol plant)(2)

Abundant CO2 Supply & No Significant Capital Required for Several Years

LaBarge Area

– Estimated field size: 750 square miles

– Estimated recoverable CO2: 100 Tcf

Shute Creek – ExxonMobil Operated

• Proved reserves as of 12/31/19: ~1.1 Tcf

• Denbury has a 1/3 overriding royalty interest and

could receive up to ~115 MMcf/d of CO2 by 2021 at

current plant capacity

Lost Cabin – ConocoPhillips Operated

– Denbury estimated to receive up to 40 MMcf/d of CO2

Gulf Coast CO2 Supply Rocky Mountain CO2 Supply

1) Reported on a gross (8/8th’s) basis.2) Planned but not currently under construction. Estimated CO2 capture date could be as early as 2023, with estimated potential CO2 volumes >200 MMcf/d.

N Y S E : D N R 30

EOR Potential >400 MMBbl at Cedar Creek Anticline

Development Summary

• Phase 1 – Red River formation development at East Lookout Butte and Cedar Hills South

– Targeting 30 MMBbls of recoverable oil; expected online 2H’22/1Q’23, with peak production 2024-25

– $150 MM development capital (excl. CO2 pipeline) to initial tertiary production; $400 MM total capital over 15-years

– Requires $150 MM CO2 pipeline to service entire CCA EOR development; represents <$0.50/Bbl across total project

– Will evaluate external capital sources for pipeline

• Phase 2 - Cabin Creek development in Interlake, Stony Mountain and Red River formations

– Targets 100 MMBbls of recoverable oil, est. development start 2024

– Est. total capex of $500 – $600 MM over multiple decades; fully funded from Phase 1 cash flow

• Future Phases – Remainder of CCA

– >300 MMBbl EOR potential in multiple formations

~105 mi. CO2 Pipelinefrom Bell Creek

Phase 2 EOR Target~100 MMBbls oil

Phase 1 EOR Target~30 MMBbls oil

~175,000 net acresEst. 5 Billion Bbls OOIP

Note: 2020+ amounts and timing contingent on Board approval, which is currently anticipated to occur in 2Q20.

N Y S E : D N R 31

(500)

-

500

1,000

1,500

2,000

2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042

CCA – Decades of Sustainable Production and Free Cash Flow

CCA Project Highlights

• Phase 1 and 2 estimated incremental tertiary production of 7,500 – 12,500 Bbls/d

– Potential to significantly increase production over time subject to CO2 availability and other factors

• Phase 1 investment, including full CO2 pipeline, attractive at $50 oil

– Initial pipeline investment benefits all incremental development

• Phase 1 payout expected within 2 years after first production at $60 oil; future phases funded from project cash flow

• Potential to generate ~$3 billion of cumulative free cash flow from Phases 1 and 2 at $60 oil

• Expect tertiary LOE to average $10-$15/Bbl

~7,500 - 12,500 net Bbls/d for Phase 1

Est. Incremental EOR Production

$ in millions ~$3 billion

~$3 billion @ $60, ~$4 billion @ $70

Est. Cumulative Net Cash Flow @ $60 oil

Future EOR Potential

Planned Phase 2Phase 1

Note: 2020+ amounts and timing contingent on Board approval, which is currently anticipated to occur in 2Q20.

N Y S E : D N R 32

CO2 EOR Development at CCA

EOR Formation Details

Initial Formations TargetedRed RiverInterlake

Stony Mountain

Field Discovery Timeframe (Oil)1930’s (Discovery)

1950’s (Development)

Formation Type Carbonate

Depth 7,000 – 9,000 ft

Original Reservoir Pressure 3,600 – 4,140 psi

CO2 Flood Type Miscible

API Gravity 29-38

Average Perm 5 md

Average Porosity 11.4%

OOIP ~5 Billion Barrels

Oil Recovered to Date ~700 Million Barrels

Est. Tertiary Recovery Factor 8 – 15%

Cedar Creek Anticline Overview

CCA Formations

1) Timing of CCA CO2 pipeline installation is contingent on Board approval, which is currently anticipated to occur in 2Q20.

N Y S E : D N R 33

Continued Mission Canyon & Charles B Success

Mission Canyon

• Drilled 12 wells to date with total program economics >90% ROR

– 9 successful wells drilled and completed 2017-2019, average IP30 ~700 Bbl/d

• Up to 12 remaining well locations after 2019 program

• 2020 plan to drill and complete 1-2 new wells

Charles B

• First well online early 1Q19; IP30 >200 BOPD; Sustained high oil cut (~80%)

• Strong potential for waterflood & EOR

• Multiple productive Charles B benches identified– 3Q19 successful delineation of upper and lower Charles B benches

– ~4.5 MMBOE waterflood recoverable resource potential

– ~12 MMBOE CO2 EOR recoverable resource potential

CCA Exploitation Program

Cedar Creek Anticline

IP30: 842 BOPD

IP30: 206 BOPD

IP30: 330 BOPD

IP30: 1,001 BOPD

IP30: 1,234 BOPD

IP30: 761 BOPD

IP30: 527 BOPD

IP30: 726 BOPD

Mission Canyon Horizontal2020 Mission Canyon HorizontalCharles B HorizontalFuture Charles B Horizontal

CCA Formations

IP30: 214 BOPD

IP30: 739 BOPD

N Y S E : D N R 34

• $52 million closed or under contract as of February 2020

– $6 million closed in 2018

– $14 million closed in 2019

– $32 million under contract

• Expect proceeds to be received in phases beginning as

early as 2H20 and concluding by mid-2022

• $30 - $50 million estimated value in remaining acreage

Houston Surface Acreage Land Sale Update

Highlights

~800 surface acres consisting of 11 commercial

parcels

Multiple parcels along I-45 frontage road

~3,400 surface acres consisting of 7 parcels for

commercial and residential development

Webster

Conroe

N Y S E : D N R 35

2019 Proved Reserves

Oil (MMBbl)

Gas(Bcf)

Total(MMBOE)

PV-10 Value(2)

(Billion)SEC Oil

Pricing(1)

Proved reserves(1) at December 31, 2018 255 43 262 $4.0 $65.56

2019 production (21) (3) (21) (0.6)

Revisions due to price changes (13) (7) (14) (1.0)

Other revisions 6 (9) 4 (0.2)

Improved recovery 1 — 1 —

Sales of minerals in place (2) — (2) —

Accretion of discount — — — 0.4

Proved reserves(1) at December 31, 2019 226 24 230 $2.6 $55.69

PDP 182 79%

PDNP 25 11%

PUD 23 10%

Total MMBOE 230 100%

Note: See “Slide Notes” on slide 43 of this presentation for footnote explanations.

N Y S E : D N R 36

Lowest Spend Among Peers as a Percent of Revenue

20%

54%

24%

43%

60%50% 50% 53% 57%

62%70% 67% 65% 65%

75%39%

10%

39%

16%

18%

21% 17%22% 17% 11%

9% 13% 16% 14%

13%

5%4%

13%10%

7%8%

9%

8% 9% 12%8% 8% 7% 8%

9%

11%13%

7% 17%

6% 11% 16%8% 11%

10% 9% 9% 10%17%

10%

75%81% 83%

87%90% 90% 91% 92% 93% 95% 96% 97% 98%

105% 108%

DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G PeerAvg

Peer H Peer I Peer J Peer K Peer L Peer M

FY19 Operating & Capital Spend as % of Oil & Gas Revenue

Spe

nd

as

% o

f R

even

ue

Source: Company filings for the year to date fourth quarter ended 12/31/2019. Peers include CLR, CRC, CRZO, CXO, LPI, MUR, MTDR, OAS, PDCE, PE, PXD, SM, WLL, and WPX. *Amounts may not foot due to rounding.

Capex LOE G&A Prod. Taxes & Transp.

N Y S E : D N R 37

Commitments & borrowing base▪ Borrowing Base / Commitment level: $615 million▪ Lender group comprised of 14 banks with largest individual commitment representing

~11% of the total

Scheduled redeterminations ▪ Semiannually – May 1st and November 1st

Maturity date ▪ December 9, 2021, subject to springing maturities beginning in February 2021

Permitted subordinated debt repurchases

▪ Up to $89 million of subordinated debt repurchases – ~$12 million of repurchases permitted as of 2/28/19– Additional ~$77 million of repurchases permitted when deleveraging or when total

leverage ratio is below 4x after giving effect to such repurchases

Junior lien debt▪ Up to $1.65 billion of junior lien debt (subject to customary requirements) (~$27 million

remaining as of 2/28/20)

Anti-hoarding provisions ▪ If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million

Pricing grid

Covenants

▪ Total Debt / EBITDAX: < 5.25x with step down to < 4.5x at 3/31/2021▪ Senior Secured Debt(1) / EBITDAX: < 2.50x▪ Interest Coverage Ratio: > 1.25x▪ Current Ratio: > 1.00x

1) Based solely on bank debt.

Senior Secured Bank Credit Facility Info

Level

Borrowing Base

Utilization

Libor margin

(bps)

ABR margin

(bps)

Undrawn

pricing (bps)V > 90.0% 375.0 275.0 50.0IV < 90.0% 350.0 250.0 50.0

III < 75.0% 325.0 225.0 50.0

II < 50.0% 300.0 200.0 50.0I < 25.0% 275.0 175.0 50.0

N Y S E : D N R 38

Production by Area

Field 2017 2018 1Q19 2Q19 3Q19 4Q19 2019

Delhi 4,869 4,368 4,474 4,486 4,256 4,085 4,324

Hastings 4,830 5,596 5,539 5,466 5,513 5,097 5,403

Heidelberg 4,851 4,355 3,987 4,082 4,297 4,409 4,195

Oyster Bayou 5,007 4,843 4,740 4,394 3,995 4,261 4,345

Tinsley 6,430 5,530 4,659 4,891 4,541 4,343 4,608

Bell Creek 3,313 4,113 4,650 5,951 4,686 5,618 5,228

Salt Creek 1,115 2,109 2,057 2,078 2,213 2,223 2,143

West Yellow Creek 13 205 436 586 728 807 640

Mature area(1) and other 7,078 6,709 6,531 6,489 6,473 6,407 6,475

Total tertiary production 37,506 37,828 37,073 38,423 36,702 37,250 37,361

Gulf Coast non-tertiary(2) 5,555 5,519 5,389 5,274 5,147 5,339 5,286

Cedar Creek Anticline 14,754 14,837 14,987 14,311 13,354 13,730 14,090

Other Rockies non-tertiary 1,537 1,431 1,313 1,305 1,238 1,192 1,262

Total non-tertiary production 21,846 21,787 21,689 20,890 19,739 20,261 20,638

Total continuing production 59,352 59,615 58,762 59,313 56,441 57,511 57,999

Property divestitures(3) 946 726 456 406 — — 214

Total production 60,298 60,341 59,218 59,719 56,441 57,511 58,213

1) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, and Soso fields.2) Includes non-tertiary production related to the sale of half of our nearly 100% working interests in Webster, Thompson, Manvel, and East Hastings fields, which is expected to close in March 2020 and averaged 1,170 BOE/d and 1,085 BOE/d

for the three and twelve months ended December 31, 2019.3) Includes production from Citronelle Field sold in July 2019 and Lockhart Crossing Field sold in the third quarter of 2018.

Average Daily Production (BOE/d)

N Y S E : D N R 39

NYMEX Oil Differential Summary

Crude Oil Differentials

$ per barrel 2017 2018 1Q19 2Q19 3Q19 4Q19 2019

Tertiary Oil Fields

Gulf Coast Region $0.06 $2.73 $4.07 $4.66 $2.88 $0.60 $3.07

Rocky Mountain Region (0.96) (1.81) (2.01) (1.36) (2.78) (3.05) (2.18)

Gulf Coast Non-Tertiary 1.26 4.28 5.45 6.06 4.69 2.79 4.77

Cedar Creek Anticline (1.43) (1.30) (2.69) (1.43) (0.91) (1.98) (1.78)

Other Rockies Non-Tertiary (2.72) (2.87) (4.80) (3.48) (3.92) (5.30) (4.35)

Denbury totals ($0.32) $1.30 $1.63 $2.35 $1.30 ($0.44) $1.23

During 4Q19, ~60% of our crude oil was exposed to Gulf Coast premium pricing

N Y S E : D N R 40

Analysis of Total Operating Costs

$ per BOE 2017 2018 1Q19 2Q19 3Q19 4Q19 2019

CO2 Costs $2.86 $3.07 $3.90 $2.81 $2.51 $2.98 $3.05

Power & Fuel 5.97 6.32 6.70 6.11 6.25 6.32 6.34

Labor & Overhead 6.32 6.61 6.71 6.95 7.57 7.22 7.11

Repairs & Maintenance 0.84 0.91 1.00 1.06 1.04 0.86 0.99

Chemicals 1.04 1.06 1.08 1.04 1.12 0.92 1.04

Workovers 2.44 2.96 2.94 2.43 2.71 2.17 2.57

Other 1.06 1.31 1.20 1.30 1.50 1.46 1.36

Total Normalized LOE(1) $20.53 $22.24 $23.53 $21.70 $22.70 $21.93 $22.46

Special or Unusual Items(2) (0.18) — — — — — —

Total LOE $20.35 $22.24 $23.53 $21.70 $22.70 $21.93 $22.46

Oil Pricing

NYMEX Oil Price $50.96 $64.81 $54.87 $59.87 $56.34 $57.02 $57.03

Realized Oil Price(3) $50.64 $66.11 $56.50 $62.22 $57.64 $56.58 $58.26

1) Normalized LOE excludes special or unusual items (see footnote 2 below).

2) Special or unusual items consist of cleanup and repair costs associated with Hurricane Harvey ($3MM) offset by an adjustment for pricing related to one of our industrial CO2 sources ($7MM) in 2017.

3) Excludes derivative settlements.

Total Operating Costs

N Y S E : D N R 41

CO2 Cost & NYMEX Oil Price

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19

Industrial-Sourced CO2 % 18% 22% 22% 23% 23% 25% 22% 22% 26% 24% 25% 28% 29% 34% 29% 28% 26% 25% 23% 25%

Tax 0.025 0.038 0.045 0.040 0.047 0.053 0.052 0.048 0.045 0.040 0.041 0.042 0.043 0.046 0.047 0.041 0.041 0.045 0.05 0.04

Purchases 0.171 0.183 0.169 0.161 0.163 0.233 0.215 0.184 0.222 0.200 0.207 0.073 0.185 0.216 0.190 0.172 0.179 0.153 0.19 0.18

OPEX 0.120 0.148 0.131 0.185 0.124 0.144 0.138 0.160 0.142 0.140 0.209 0.166 0.167 0.183 0.171 0.210 0.171 0.132 0.12 0.12

NYMEX Crude Oil 48.83 57.99 46.70 42.15 33.73 45.56 45.02 49.25 51.95 48.32 48.12 55.48 62.96 67.85 69.60 58.81 54.87 59.87 56.34 57.02

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

$0.45

$0.50

NYM

EX C

rud

e O

il Pr

ice

/ B

bl

CO

2C

ost

s /

Mcf

(1)

1) Excludes DD&A on CO2 wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO2 costs.2) CO2 costs include workovers carried out at Jackson Dome in 3Q17 and 4Q15 of $3 million ($0.08 per Mcf) and $3 million ($0.05 per Mcf), respectively, and a downward adjustment in 4Q17 for pricing related to one of our industrial CO2 sources of $7

million ($0.12 per Mcf).

OPEX Purchases Tax NYMEX Crude Oil Price

Industrial-Sourced CO2 %

(2) (2) (2)

N Y S E : D N R 42

Reconciliation of net income (loss) (GAAP measure) to adjusted EBITDAX (non-GAAP measure)

Adjusted EBITDAX is a non-GAAP financial measure which management uses and is calculated based upon (but not identical to) a financial covenant related to “Consolidated EBITDAX” in the Company’s senior secured bank credit facility, which excludes certain items that are included in net income (loss), the most directly comparable GAAP financial measure. Items excluded include interest, income taxes, depletion, depreciation, and amortization, and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring. Management believes Adjusted EBITDAX may be helpful to investors in order to assess the Company’s operating performance as compared to that of other companies in its industry, without regard to financing methods, capital structure or historical costs basis. It is also commonly used by third parties to assess leverage and the Company’s ability to incur and service debt and fund capital expenditures. Adjusted EBITDAX should not be considered in isolation, as a substitute for, or more meaningful than, net income, cash flow from operations, or any other measure reported in accordance with GAAP. Adjusted EBITDAX may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDAX, EBITDAX or EBITDA in the same manner.

2018 2019

In millions Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 Q4 FY

Net income (loss) (GAAP measure) $40 $30 $78 $174 $323 $(26) $147 $73 $23 $217

Adjustments to reconcile to Adjusted EBITDAX

Interest expense 17 16 19 18 70 17 20 23 21 82

Income tax expense (benefit) 14 9 16 48 87 (11) 65 37 13 104

Depletion, depreciation, and amortization 52 53 51 60 216 57 58 55 63 234

Noncash fair value losses (gains) on commodity derivatives 15 41 (17) (236) (196) 92 (26) (35) 64 94

Stock-based compensation 3 3 4 3 12 3 4 3 3 12

Litigation accrual and loan receivable impairment — — — 67 67 0 0 0 — —

Gain on debt extinguishment — — — — — — (100) (6) (50) (156)

Severance-related expense — — — — — — — — 19 19

Noncash, non-recurring and other 1 1 (3) 7 5 6 1 (5) (1) 1

Adjusted EBITDAX (non-GAAP measure) $142 $153 $148 $141 $584 $138 $169 $145 $155 $607

Non-GAAP Measures (Cont.)

N Y S E : D N R 43

Non-GAAP Measures (Cont.)

Reconciliation of the standardized measure of discounted estimated future net cash flows after income taxes (GAAP measure) to PV-10 Value (non-GAAP measure)

PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. Denbury’s 2019 and 2018 year-end estimated proved oil and natural gas reserves and proved CO2 reserves quantities were prepared by the independent reservoir engineering firm of DeGolyer and MacNaughton. The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932. Management believes PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the Standardized Measure can be impacted by a company’s unique tax situation, and it is not practical to calculate the Standardized Measure on a property-by-property basis. Because of this, PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific properties. PV-10 Value is commonly used by management and others in the industry to evaluate properties that are bought and sold, to assess the potential return on investment in the Company’s oil and natural gas properties, and to perform impairment testing of oil and natural gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized Measure. PV-10 Value and the preliminary Standardized Measure do not purport to represent the fair value of the Company’s oil and natural gas reserves.

December 31,

In millions 2018 2019

Standardized Measure (GAAP Measure) $3,351 $2,261

Discounted estimated future income tax 674 355

PV-10 Value (Non-GAAP Measure) $4,025 $2,616